Wellbore stability problems are common in the drilling of oil and gas wells. Wellbore instability is indicated when a wellbore collapses causing pipe sticking, when unstable formations slough cavings into the wellbore, or when a wellbore excessively enlarges. The formations that usually cause wellbore instability are shale and mudstone. A shale is a relatively impermeable formation that contains compacted fine grain sediments and reactive clays. Usually, shale formations are low strength, plastically deformable rocks that are reactive to drilling fluids.
Shale formation evaluation has historically been to identify the types and amounts of clays in the formation, to gauge the degree of dispersion of unstressed cuttings when exposed to mud, and to measure the unstressed swelling of the shale when exposed to fluids. These evaluation techniques fail to consider any rock mechanical properties, and therefore, have not proven to be very effective in predicting wellbore stability or as aides for choosing drilling muds that prevent or delay wellbore destabilization.
The triaxial compression test is the most common test method used to investigate rock mechanical properties. In the triaxial test, a jacketed cylindrical rock sample is axially loaded while a confining pressure is applied. In many cases the testing is made without provision to control rock pore fluid pressure, this is described as undrained tests. When pore fluid pressure is measured and controlled, the test is considered a drained test. Typically, the axial load is compressive and increased while holding the confining pressure constant until the rock sample reaches some maximum axial distortion. Determination of rock mechanical properties using triaxial apparatus in drained and undrained modes is commonplace in mining and excavating activities.
In the conventional triaxial test and in most analyses of rock stresses, the force components of the loading on the rock specimen are resolved into three principal components, .sigma..sub.1, .sigma..sub.2, and .sigma..sub.3, with .sigma..sub.1 .gtoreq..sigma..sub.2 .gtoreq..sigma..sub.3. In the triaxial test, .sigma..sub.1, the greatest principal stress is the axial load and .sigma..sub.2, the intermediate principal stress, equal to .sigma..sub.3, the least principal stress, and applied by confining pressure. The confining pressure is a hydraulic pressure provided by a hydraulic fluid such as oil or water inside the test cell. Most of the testing done to date has been related to determining a maximum axial stress (or .sigma..sub.1) achieved under test conditions. This value is generally considered the compressive strength of the material. Another test method that utilizes more complicated means of applying strains and stresses is called the polyaxial test. Square cross section rectangular rock specimens are loaded axially as in the triaxial test, but, instead of a confining pressure, a system of four flat-jacks or a system of pistons provide lateral restraint. Using apparatus like these, values of intermediate principal stress greater than the least principal stress are possible. Analysis of test results for both the triaxial test and the polyaxial test is simplified by the application of homogeneous stresses to the sample.
The current method for determining well bore stability is to obtain shale samples from downhole cores or surface outcroppings, determine the mechanical properties of the sample with a series of triaxial tests, estimate the downhole stresses and calculate the maximum stress level that allows the wellbore to remain stable. The calculation method used for this will be based on some yield criterion. As described in G. F. Fuh's "Use of Borehole Stability Analysis for Successful Drilling of High-Angle Hole", the most widely used stability criteria is called the Extended Von Mises yield criteria. This mechanical approach to the stabilization of wellbores will probably fail in many situations.
This has proven inadequate because a number of areas where the triaxial tests may be misleading when related to wellbore stability have been identified. They fall into two categories. The first category relates to mechanical factors and their incompatibility with a drilling wellbore. These factors include the geometry of the test, the loading path and strain rate for the test, and the destructive nature of the test. The second category relates to the drilling fluid and the effects of exposure on the rock properties under downhole stress conditions. These factors include the hydration of the clay containing shale when exposed to drilling fluids, osmotic effects that may cause formation strengthening or weakening, cation exchanged phenomena that may alter the strain behavior, and chemical alteration from alkali that can prevent or promote rock failure.
The failure characteristics of many materials can depend on the order and timing of stress application. Field experience and laboratory testing to date indicates that shale is one of these materials that is load path dependent. Post failure properties are even more load path dependent than the failure characteristics with sedimentary rocks. In almost all cases of wellbore instability, the evidence of failure is not immediate, but occurs days, weeks, or even months after the wellbore is drilled and prior to running of casing. This suggests that the failure of the rock occurs after a long period of time under a high stress level. Conventional testing cannot re-create these long periods at high stress levels because the rock fails quickly in a conventional triaxial test under steadily increasing axial stress at high strain rates. Using a constant stress level over a long period of time is not practical as it would effectively keep expensive test equipment occupied for a prolonged period, unacceptably reducing equipment throughput. Also, since most rock weakening occurs with exposure to drilling fluids, conventional equipment (triaxial and polyaxial test cells) would not determine fluid effects.
Both of the test methods discussed to this point, triaxial testing and polyaxial testing, rely on sample failure to determine the ultimate strength of the rock. Changes in the rock with different confining stresses cannot be gauged without the stressing of the rock to a failure point. This sort of testing requires that many samples be tested to explore the rock failure "envelope" for a particular rock sample. With most plastic rocks like the shales, a minimum of two triaxial tests are required to adequately describe the rock failure mechanism. If long term loading effects and the effect of intermediate principal stress are also to be gauged, a long term research project is probably required. Large scale research projects, aside from being costly, are not practical in a field service environment and certainly are not desirable situations for someone trying to drill a troublesome shale.
The destructive nature of these tests poses interesting questions when interpretation of the results is needed. This is particularly true when the results are to be used to gauge the stability of a wellbore. Information from mining and excavation processes indicates that proper support of failed rock can produce a stable excavation, even with the strength of the material exceeded in portions of the rock body. The fact is that shear failure of rock surrounding a wellbore does not imply that wellbore is unstable. Determining if failed rock can support enough of the rock stresses requires a geometry more comparable to the wellbore than the conventional tests.
Hydration of clays that exist within the shale matrix are felt to increase the effective stress on the shale body. These increases in effective stress can reduce the strength of a shale and cause it to fail. The quantification of hydration effects is particularly difficult as the effects are dependent on the previous stress state and current stress state. Exposure of shale to in situ stress levels and drilling fluid is the most applicable method assess hydration effects. One approach used today has been to triaxially stress a shale sample and drill in with a mud.
Related to hydrational stresses, osmotic effects reflect the different salts and salt concentration present in the drilling fluid and shale. When the salt concentration between the mud and the shale is different, and osmotic pressure exists that can cause fluid diffusion from the shale into the mud. This diffusion can help destabilize a wellbore. Primary osmotic effects are not stress related, but secondary osmotic effects from hydrational pressures can be significant.
Clays occur with charge deficiencies within their crystalline structure that encourages the adsorption of cations like sodium (Na+), potassium (K+), and calcium (Ca++). Under the right conditions of temperature, stress, and concentration, the clay's existing adsorbed cations can be displaced by another species of cation. This can cause the clay to change properties and will affect the properties of a shale containing these clays.
The chemistry of a mud can have a profound effect on the fabric of a shale. Alkali in the mud can cause the weakening of the shale or can alter it to form a stronger material. The presence of clay dispersants and deflocculants can cause softening of the wellbore surface. Chemical alteration and shale stability should be determined at downhole conditions. Chemical alteration effects can be much different for shale in an unstressed state compared to effects in a stressed state.
Heretofore, many processes have been utilized in attempting to test shale under conditions of near downhole stress. Polyaxial and triaxial compression tests have been attempted. However, these methods have not been overly successful because they fail to consider rock mechanical properties and the effects to the sample because of conditions of downhole stress and pore pressure with exposure to drilling fluid at in situ temperature and pressure. There is therefore a need for an improved apparatus and method of evaluating rock properties under downhole conditions that is easy and cost effective to conduct.